As wells get deeper requiring rigs with high day rates it becomes more important to streamline operations to save trips in the hole. Fracturing is a completion method that enhances subsequent production by directing high pressure fluid with high flow rates at perforations or at selectively opened ports in casing or in open hole.
In the last five years North America has changed the oil and gas markets by using horizontal drilling and multistage hydraulic fracturing to unlock the hydrocarbons in low-permeability reservoirs. These plays require new technologies that enable reservoir characterization, horizontal drilling, multistage completions, and multistage hydraulic fracturing. The purpose of a completion string is to provide the services and tools needed to turn a drilled well into a producing well. In unconventional reservoirs the completion has two primary functions. It is a way to isolate multiple stages in the wellbore and hydraulically fracture individual stages, and to provide a conduit to produce hydrocarbons through. Three completion techniques have emerged as the most effective and efficient in these types of formations; plug and-perforate, ball-activated completions (offered by Baker Hughes Inc. under the name FracPoint™), and coiled tubing-activated completions (offered by Baker Hughes Inc. under the name OptiPort™). Each of these completions has considerations.
Plug-And-Perforate
The plug-and-perforate technique typically uses cement to isolate the annulus between the open hole and the liner, perforations (perforations) to regain communication with the wellbore at the desired location, and composite frack plugs to provide through tubing isolation from the stages below. This technique starts by running pipe, called liner, into the open hole and cementing it in place. The cement hardens, and the rig is then moved off location. Because the liner is cemented in place there is no communication to the formation. Without communication tools cannot be pumped down, so the first stage perforations are run using coiled tubing, a wireline tractor, or a workover rig. The perforations penetrate though the liner and into the formation, creating an injection point for the fracture treatment. Once the first stage is perforated, the running assembly is pulled out of hole, the fracking crew rigs up, and the first stage fracture is performed through these perforations. The perforations also reestablish fluid flow into the formation, so a pump down assembly on wireline can be used for the remaining stages. From bottom to top, the pump down assembly consists of a composite frack plug, a plug setting tool, and perforation guns. All of these tools are operated by the electrical signals sent through the wireline. This assembly is pumped downhole and when it reaches the appropriate depth, a signal is sent through the wireline which sets and then releases the plug. The perforating guns are then pulled up hole to the intended perforation depth. These guns are often select-fire guns that will selectively fire sections of the guns independently. A signal is sent to fire the first section of the guns. The guns are then pulled up hole to the next perforation depth, and another signal is sent to fire the second section of the guns. This process is repeated until all of the selected depths are perforated. This technique is called cluster perforating. When the perforations for that stage are complete, the wireline is pulled out of hole, rigged down, and the fracking crew rigs up to fracture this zone. After the fracking is complete, the fracking crew rigs down and the wireline is rigged up with another pump down assembly. This process is repeated until all stages are fractured. When the fracking process is complete, the plugs are milled up and the well can be put on production.
FracPoint
The FracPoint system offered by Baker Hughes Inc. was designed to provide multistage isolation in open hole. It uses open hole packers to isolate the annulus between the open hole and the liner and ball-activated frack sleeves to divert the fracture and isolate individual stages. The frack sleeve contains a ball seat that corresponds to a frack ball. Because this system is completed in open hole and uses ball activated sleeves to divert the fracture, there are no cementing or wireline operations required. The FracPoint components are run in the hole on liner and strategically placed and spaced out to isolate and fracture the desired stages. The completion string is often hung in the well using a casing packer in the intermediate casing. A float shoe is run at the toe of the completion, and acts as a check valve to isolate the well through the liner while running in hole. Once the intended depth is reached, the first ball, which is also the smallest ball, is circulated down to the wellbore isolation valve (WIV). Once the ball seats, applying pressure closes the WIV, essentially creating a bull plug that will not allow flow through the liner from either direction. Now that the WIV is closed, the hydraulic-set packers and casing packer can be set by applying the appropriate amount of pressure. At this point the rig can be moved off of location, because the WIV provides through tubing isolation in the liner and the casing packer isolates the annulus. When the frack crew arrives and rigs up, the pressure activated sleeve (P-sleeve) is opened by simply applying the appropriate amount of pressure (which is much higher than the packer setting pressure), and the first stage fracture can begin. Once the first stage fracture is complete, a flush of clean fluid is pumped between the first and second stage to clean out any proppant that has settled in the liner. The pump rate is briefly slowed down and the ball corresponding to the second stage is dropped into the well, and pumped down the first ball activated sleeve. The balls and ball seats in the frack
sleeves have different size increments with the smallest being at the toe and the largest being at the heel, so that all of the balls can pass through the other ball seats and land on the corresponding seat. When the ball lands on seat, pressuring up will shift the sleeve open, and the second stage fracture can begin. This process is then repeated until all stages are fractured. After the fracture, the ball and ball seats can be milled up, but it is not required unless a full liner diameter is needed. An alternative to the hydraulic-set open hole packer is the reactive element REPacker™ offered by Baker Hughes Inc. This packer is fluid-activated, so it is set by circulating a setting fluid over the packer and simply giving it time to swell. These can be custom made for the application depending on the pressure ratings and well parameters. Another option to consider is the re-closable CMB frack sleeves offered by Baker Hughes Inc. The CMB sleeves can be closed and reopened with a coiled tubing shifting tool. These can be used to isolate water producing stages, or used to re-isolate the liner for re-fracturing purposes.
OptiPort
The OptiPort system offered by Baker Hughes Inc. is a coiled tubing-activated multistage hydraulic fracturing completion. This system has the versatility to use either cement or open hole packers to isolate in the annulus. The OptiPort pressure-balanced frack collars provide the medium for the frack fluid to enter the selected portion of the formation, and a coiled tubing (CT) packer is used to open the frack collars and isolate through tubing from the stages below. The frack collars have internal ports that are exposed to the internal pressure of the liner. As long as both ports have the same pressure applied, the sleeve will not open. The intended collar is opened by setting a CT packer between these two pressure ports and applying annular pressure. This causes a pressure imbalance because the packer only allows the pressure to be applied to the top port, but not the bottom port. The pressure imbalance shifts open the intended collar, but the unopened collars remain pressure balanced and closed. Like the FracPoint system, the OptiPort system is run in hole and strategically spaced out on a liner string, but the liner is often ran back to surface and hung on the wellhead. Once the string reaches the setting depth, the system is cemented in place or the open hole packers are set, and the rig is moved off of location. When it comes time to fracture, a CT unit is brought out to location and the bottom hole assembly (BHA) is set up with a casing collar locator (CCL), CT packer, and circulation sub. The CT BHA is run to the bottom of the well and the CCL is used to locate the first frack collar. When the correct depth is located, the CT packer is set between the two internal pressure ports on the OptiPort collar. Pressure is applied to the CT annulus and the intended collar opens, while all other remain in a pressure-balanced and closed position, and the first stage fracture is performed through the annulus of the liner and the CT. When the frack is complete, the pumping units are shut down. Applying a pulling force on the packer releases it, and it is moved up hole to the next stage. The CCL locates the second frack collar and the CT packer is reset, pressure is applied, the second collar is opened, and the frack for this stage is performed. This process is then repeated until all stages are fractured. If there is a scenario where the fracture flow area in the CT is larger than the flow area of the annulus, the BHA can be set up to fracture down the coiled tubing.
Plug-And-Perforate Considerations
Number of stages—virtually unlimited, only limited by the length of the wireline and CT.
Stage placement—the placement of the stage is not final until the perforations are fired, sochanging the placement can be done on the fly by moving the perforating guns up or down the well.
Contingency options—there aren't any diameter restrictions above the stage being fractured, so it is possible to use through tubing tools should there be any issues.
Fracturing logistics—pressure pumping is not the only service required during the fracking operation, wireline and/or coiled tubing is needed as well.
Fracturing operation efficiency—Both pressure pumping and wireline have to be rigged up and rigged down between each stage.
Post fracture—the composite frack plugs will require mill out, but there is a full production diameter afterwards.
Re-fracturing options—straddling the perforations with through-tubing tools is the only way to provide isolation, causing a reduction in flow diameter which could limit the parameters of the re-fracture.
The flexibility of stage placement can be a huge benefit in the appraisal phase. Additional data can be gathered with logs, micro-seismic, and other tools, and the stages can be adjusted on the fly if needed.
FracPoint Considerations
Number of stages—the number of stages is limited to the number of ball and ball seat combinations, but technology has tightened that gap by allowing 40 individual ball and ball seat combinations.
Stage placement—once the system is set, the stages are fixed at the depth of the frack sleeves.
Contingency options—very limited contingency options due to diameter restrictions in the ball seats hindering the use of through tubing tools.
Fracturing logistics—Only pressure pumping required.
Fracturing operation efficiency—Nonstop fracturing operations, only slowing down briefly to drop the frack ball.
Post fracture—no mill out required, but the production diameter will be restricted if the ball seats are not removed.
Re-fracturing options—re-closable frack sleeves leave the option of completely re-isolating the liner string, providing a variety of different re-fracturing options.
The combination of improved logistics and nonstop fracturing are the big advantages with this completion system. These advantages drive efficiency during the fracture process.
OptiPort Considerations
Number of stages—virtually unlimited, only limited by the length of the CT.
Stage placement—once the system is set, the stages are fixed at the depth of the frack collars
Contingency options—CT is already in hole and the BHA is set up to be able to circulate should any issues occur.
Fracturing logistics—both pressure pumping and coiled tubing required.
Fracturing operation efficiency—fracturing briefly shuts down between each stage to release the CT packer and move to the next stage□ Post fracture—full production diameter with no mill out required.
Re-fracturing options—straddling the perforations with through-tubing tools is the only way to provide isolation, but this was an annular frack, so the original frack parameters can most likely be matched.
Having coiled tubing in the hole while fracturing has offers several benefits. Having efficient contingency options can allow a more aggressive frack plan, because screenouts can be cleaned out with little nonproductive time. Also, it allows real time down hole pressure monitoring through the static column of fluid inside of the CT.
FIGS. 1-12 illustrate a known sequence of isolating intervals already perforated from new intervals to be perforated where the method requires a trip out of the hole every time an interval is perforated and then fractured to grab another isolation device that is then set above the recently perforated interval so that the next interval can be perforated. In FIG. 1 a perforating gun 10 is run to the bottom of the well using coiled tubing, wired tubing, wired pipe, one-trip wired drillpipe casing, wired pipe or a wireline tractor and fired as shown in FIG. 2. FIG. 3 shows the guns 10 removed from the borehole 12 and the perforations 14 are then fractured by pressuring up the entire borehole 12 so as to create pathways or fractures 16 for subsequent production. Now as shown in FIG. 4 another gun 18 with a plug 20 is run in and the plug 20 is set in FIG. 5 to isolate the fractures 16 created in FIG. 3. The gun 18 is shot to make perforations 22 that are then fractured to create fractures 24. In FIG. 7 another gun 26 with a plug 28 below is run in and plug 28 is set above fractures 24. Perforations 30 are made with gun 26 and fractures 32 result from a fracturing operation as shown in FIG. 9. FIGS. 10-12 show a mill 34 sequentially milling the plugs 20 and 28 so that the borehole 12 is ready for production.
Clearly the above illustrated method has disadvantages of multiple trips into the hole and a time consuming milling operation as well as the cost of the isolation devices that are milled up. Other systems that use rupture discs and suggest a one trip multiple interval completion are discussed in U.S. Pat. No. 7,096,954.
The present invention is focused on a one trip system using guns and a releasable barrier as well as logging tool and instrumentation to allow staying in the hole after isolating a lower interval and fracturing while perforating the adjacent interval. Pressure is built up before the gun is fired in a new interval to enhance the fracture formation. Pressure is boosted at the bottom hole assembly to aid in the fracturing and for rapid deployment of the resettable barrier that is preferably an inflatable. In this manner the borehole is not fully pressurized for the fracturing. The assembly is run in with a tractor or on coiled tubing that can have an internal cable for the instrumentation that gives real time feedback as to pressure and flow conditions or seismic conditions during the fracture and powers other logging equipment so that the gun can be placed at an optimal location in any given interval. Optionally, the BHA can be pumped to the desired location using a known volume of water to minimize water consumption when pumping down the BHA on wireline, for example. Barrier milling is not required as the barrier is simply released and removed from the borehole. These and other aspects of the present invention will be more readily apparent to those skilled in the art from a review of the description of the preferred embodiment and the associated drawings while recognizing that the full scope of the invention is to be determined from the appended claims.